While gains in horizontal drilling efficiencies have driven a large part of the U.S. onshore energy boom over the last five years, completion techniques "need to close the gap," and better assist in reducing costs and maximizing returns, according to a group of panelists at the DUG East Conference in Pittsburgh earlier this month.
"Pad drilling allows you to experiment; it's a natural laboratory," said Weatherford International Ltd.'s Director of Strategic Marketing Robert Fulks. "You have one well here, one well here, the next well and so on, and you can do a little bit of everything. You could run one fluid design here, another fluid design there; you could run sliding sleeves and be doing zipper fracks or another method nearby to complete the well."
Whether it's simultaneous completion operations on multiple wells, or zipper fractures (fracks), on-site storage of proppant and chemicals, closer analysis of the source rock at every step of the drilling and completions process, or simply better communication between the service provider and customer, Fulks said oilfield services companies like his have a lot of room to grow with the exploration and production companies they work for.
Fulks recounted a recent completions job at a Chesapeake Energy Corp. site in West Virginia. He said Weatherford was making a just-in-time delivery of the proppant and solvents needed to prepare the well for production. Those supplies made it, but if anything had gone wrong, it could have derailed the entire completions schedule.
"The weather was good. I could see the situation would not have been anywhere near where it was had there been bad weather," Fulks said. "There was a large road going up to the location and that could have been a problem. It also worked well because this was an eight-well pad at a small location. You have to anticipate the bad weather, we had a pretty terrible winter up here and things got far behind."
Fulks and other panelists said as the number of wells increase in across the country, more chemicals and proppants will have to be stored onsite to ensure a reliable supply.
As operators realize the production benefits, proppant consumption has rapidly increased in the nation's leading onshore basins. In February, PacWest Consulting Partners forecast that the market would grow overall by 10% from 2013 through 2015 (see Shale Daily, Feb. 5, 2014).
"We've certainly seen proppant volumes double over the last eight to 10 months," said Baker Hughes Inc.'s Central Geomarket Vice President Iain McIntosh. "Our customers are not skimping on the frack, they're pumping as much as they can these days. It presents transportation and logistical challenges, and it plays right into what Robert said that we're going to have to find ways to store larger amounts of this stuff at drill sites."
Fulks said his company has seen sand usage alone grow at a compound rate of 32.5% over the last two years in the Appalachian Basin, while in the first three months of this year, it's increased another 50% over that. Some operators, he said, have gone from using about 2.4 million pounds of sand in their wells to as much as 11 million pounds.
"What's happened is yes, you are getting better production out of that and it works in certain areas better than others," Fulks said. "But it has cost in the logistics and supply chain to do this. Let me just clear this up, there is not a shortage of sand. There's plenty of sand out there, that's not the issue, it's the logistics part of getting it there."
An increase in drilling and more demand for services, panelists said, have led to a small increase in the cost it takes to get things such as sand and solvents to well sites.
Multiple pay horizons, with operators targeting the Utica, Marcellus and Upper Devonian formations, are also offsetting the cost reductions of recent years as subsurface mechanics get more tricky. This has led engineers and oilfield services companies to continue their quest to find cost-cutting measures.
"As the economics become more challenging above and below the surface, it calls for us to work a little closer with the customer to make sure that we have the right solutions and that we're communicating in a way that makes us cost-effective," McIntosh said. "It's the state of the game today."
Although multi-well pads are enabling more laterals to target different formations, talk also continued at DUG East about the potential of multi-lateral wellbores.
"I think I look at it almost every year for about 10 minutes," said Rex Energy Corp. Director of Drilling Casey McDonough. "But it's almost easier and cheaper to drill another well bore. I've thought about this long and hard, being able to isolate the pressures required to frack these shales is difficult with a multi-lateral-type wellbore."
Anadarko Petroleum Corp.'s Jonathan Floyd agreed. He is the producer’s drilling operations manager for the Marcellus. Anadarko has increasingly been drilling longer on the lateral, in some cases drilling 10,000 horizontal feet into the Marcellus. Multiple wellbores, he said, will likely be the norm for some time.
"We've seen in looking at a multi-lateral system that it's not quite there yet on the economics," he said. "For now, it makes more sense to drill another wellbore."
The panelists said the time it takes to drill and complete horizontal wells has reduced dramatically in the last five years, but a plateau could be nearing for stable well costs as operators look to do more with each pad they construct, while facing more regulations. Producers also want the high-spec, walking rigs, which are more expensive (see Shale Daily, April 24).
"I think the costs will continue to come down, but what's driving them up is title costs, more regulatory, higher environmental controls and the things that we have to be cognizant about like rotating casing and getting good cement jobs -- being more environmentally responsible," McDonough said. "Those sort of efficiencies will offset higher rig costs that are going to come with these difficult well bores."